Biogas typically refers to a mixture of different gases produced from the breakdown of organic matter without oxygen in an anaerobic digestion process. Biogas can be produced from raw materials such as agricultural waste, manure, municipal waste, plant material, sewage, green waste or food waste. Biogas typically comprises as the main components 50-70% of methane (“CH4”) and 20 to 50% carbon dioxide (“CO2”), with lower levels of other components such as N2 and O2, up to 5,000 ppm or more of hydrogen sulfide (“H2S”), siloxanes, up to 1,000-2,000 ppm of volatile organic compounds (“VOC's”), and is saturated with water. Biogas also includes landfill gas (“LFG”), which is derived from solid waste landfills that decompose to the organic waste with time, via microbe digestion of the variety of organic waste to produce methane and CO2. In either case, biogas includes high concentrations of methane and carbon dioxide, water vapor, and lesser concentrations of VOC's and other contaminants.
Specifically, digester biogas (“digester gas”) or landfill gas is a type of renewable energy. Methane or natural gas is a combustible fuel for supplying energy, and also as a raw material in many industrial significant processes. Thus, it is very desirable from an economic and environmental viewpoint to capture the methane from digester or landfill exhaust gas, especially since biogas is a renewable source and not a fossil fuel.
If digester and landfill exhaust gas is not recovered, the methane that escapes into ambient air becomes a source of air pollution. Accordingly, it is further desirable to prevent the methane emissions produced from the anaerobic digestion, for environmental protection purposes. Traditionally, digester or landfill exhaust gas has been burnt in an open flame incinerator such as a flare stack, to prevent the gas from escaping to the environment. This burning process is inefficient, and consequently, a large fraction of the methane and other obnoxious contaminants in the exhaust gas survive to pollute the ambient air. Further when combusted CO2, a potent greenhouse gas, is emitted. Also, common flare stack operations are a waste of the useful energy held by the methane in the exhaust gas.
Other conventional methods for recovering methane from digester and landfill exhaust gas, and other sources of crude natural gas have developed. These methods include gas separation processes in which the useful methane is separated from other components of the source gas. Favored conventional gas separation processes typically utilize adsorption-regeneration technology, in which the crude gas is processed by an adsorbent material that passes selected components of the crude and rejects others. For example, pressure swing adsorption (“PSA”) or Thermal Swing Adsorption (“TSA”) technologies involve selectively adsorbing contaminants of crude gas onto adsorbent particles, and allowing the so-called sweetened gas to pass through the PSA/TSA units.
Unfortunately, the adsorbent particles in the PSA/TSA units ultimately become saturated with the contaminants, and lose their abilities to adsorb beyond a maximum amount. Therefore, before more contaminants can be removed from the crude, the adsorbent particles must be regenerated. The regeneration process normally involves exposing the saturated particles to high temperatures and/or low pressures, and regeneration with fluids that have low concentrations of the contaminants to promote desorption of the contaminants from the particles. For example, TSA requires a supply of heat energy to heat the regeneration gas and PSA requires a supply of clean, usually low pressure gas. Additionally, the adsorption-regeneration technology also requires support facilities for removal of water vapor, and pre-conditioning the crude gas, e.g., by compressing it to high pressure. Thus, it is very costly in financial and energy consumption aspects to operate conventional adsorption-regeneration technologies, to recover useful methane from digester and landfill exhaust gas.
On the contrary, membrane systems are versatile and are known to process a wide range of feed compositions and separations. With a very compact footprint and low weight, these membrane systems are well suited for offshore applications, remote locations, or for smaller flow rates. Recent developments in dew point control include membrane designs that operate in condensing mode, as well as membranes that allow for the simultaneous removal of water and heavier hydrocarbons from natural gas.
Membranes have been used for biogas treatment. Typical membrane processes involve first removal of H2S by a sulfur removal unit, a further pretreatment by refrigeration and adsorption processes to remove water and VOCs, then followed by a two-stage membrane process that is dedicated to CO2 removal, and further recycling/processing of the permeate from the second separation stage of membrane. U.S. Pat. No. 8,999,038 and WO 2016/107786, both assigned to Evonik Fibres GMBH, disclose a three-stage membrane process for CO2 removal using membranes with CO2/CH4 selectivity higher than 50. These processes do not simultaneously remove H2S and CO2 while achieving high methane recovery (≥94%).
It is also well documented that glassy polymers, such as polyimide, polysulfone, polybenzimidazole, etc., exhibit exceptional high intrinsic CO2/methane selectivity. However, the selectivity and permeance of the membranes prepared from those materials often quickly decrease, once they are used for methane gas extraction in the presence of VOC's and other biogas impurities. This loss of membrane performance is caused by condensation and coating of the VOC's and siloxanes on the membrane surface or due to adsorption of the heavy components in the membrane fiber. The conventional solution for this problem is to use a system including a regenerable adsorbent bed, followed by a carbon trap for removing the water, siloxanes and VOC's upstream of the membrane used for CO2 removal. Although these pretreatment systems can effectively remove VOC's and other components from the biogas stream, the cost of the pretreatment and/or frequent membrane replacement can be prohibitive. Indeed, the cost of the pretreatment system can be as high as 50% of the total system cost (pretreatment plus membrane).
Further, the product gas produced from digester gas and landfill gas must meet safety criteria to be injected into the utility pipeline. In particular, a common industry standard aims to comply with SoCalGas® Rule 30 and PG&E Rule 21, which set forth the standards for utility methane gas injection in large portions of California. Specifically, according to Rule 30, the methane gas to be delivered should have:
a) Heating Value: The minimum heating value of nine hundred and ninety (990) Btu (gross) per standard cubic foot on a dry basis, a maximum heating value of one thousand one hundred fifty (1150) Btu (gross) per standard cubic foot on a dry basis.
b) Moisture Content or Water Content: For gas delivered at or below a pressure of eight hundred (800) psig, the gas shall have a water content not in excess of seven (7) pounds per million standard cubic feet. For gas delivered at a pressure exceeding of eight hundred (800) psig, the gas shall have a water dew point not exceeding 20° F. at delivery pressure.
c) Hydrogen Sulfide: The gas shall not contain more than twenty-five hundredths (0.25) of one (1) grain of hydrogen sulfide, measured as hydrogen sulfide, per one hundred (100) standard cubic feet (4 ppm). The gas shall not contain any entrained hydrogen sulfide treatment chemical (solvent) or its by-products in the gas stream.
d) Mercaptan Sulfur: The gas shall not contain more than three tenths (0.3) grains of mercaptan sulfur, measured as sulfur, per hundred standard cubic feet (5 ppm).
e) Total Sulfur: The gas shall not contain more than seventy-five hundredths (0.75) of a grain of total sulfur compounds, measured as a sulfur, per one hundred (100) standard cubic feet (12.6 ppm). This includes COS and CS2, hydrogen sulfide, mercaptans and mono, di and poly sulfides.
f) Carbon Dioxide: The gas shall not have a total carbon dioxide content in excess of three percent (3%) by volume.
g) Oxygen: The gas shall not have an oxygen content in excess of two-tenths of one percent (0.2%) by volume, and customer will make every reasonable effort to keep the gas free of oxygen.
h) Inerts: The gas shall not contain in excess of four percent (4%) total inerts (the total combined carbon dioxide, nitrogen, oxygen and any other inert compound) by volume.
i) Hydrocarbons: For gas delivered at a pressure of 800 psig or less, the gas hydrocarbon dew point is not to exceed 45° F. at 400 psig, or at the delivery pressure, if the delivery pressure is below 400 psig. For gas delivered at a pressure higher than 800 psig, the gas hydrocarbon dew point is not to exceed 20° F., measured at a pressure of 400 psig.
These gas constituent limits restrict the concentration of gas impurities to protect pipeline integrity, and ensure safe and proper combustion in end-user equipment. In particular, the hydrocarbon dew point requirement and the reduction of heavy hydrocarbons prevent unsafe formation of a liquid phase during transport. The hydrocarbon dew point is sensitive to small quantities of C6+ and VOC components. As little as 450 ppm of C8 hydrocarbon added to a lean gas can give it a cricondentherm of 50° F.
There are other known attempts to produce purified methane from biogas or natural gas.
U.S. Pat. No. 7,025,803 to Wascheck, et al. recovers high concentrations of methane from crude natural gas and solid waste landfill exhaust gas, using a sequential combination of a pressure swing adsorber unit operation to remove volatile organic compounds from the crude feed gas mixture, followed by an activated carbon bed, and a membrane separation unit operation. However, the system in '803 is relatively costly for some system operators and does not satisfactorily handle relatively high levels of H2S. Therefore, a separate H2S removal system (such as SulfaTreat or other treatment methods) may be required for raw biogas containing relatively high H2S levels, and an activated carbon bed may be required for reaching a desirably low VOCs level.
U.S. Publication No. 2017/0157555 to Karode, et al. teaches purification of natural gas by removing C3+ hydrocarbons and CO2 in respective first and second gas separation membrane stages to yield a conditioned gas that is lower in C3+ hydrocarbons and CO2, in comparison to the un-conditioned natural gas. The '555 publication is not concerned with producing biomethane, or removing VOC's and siloxane from biogas. Further, product gas from natural gas sweetening typically contains a mixture of methane, ethane, and natural gas liquids.
PEEK membranes previously marketed by Porogen (now Air Liquide) remove sulfur gas (H2S), but have a relative low selectivity for CO2 over CH4.
Therefore, there remains a need for processing biogas or landfill gas in a membrane gas separation system, to remove VOC's, siloxane, H2S, CO2 and other impurities, as well as to achieve dehydration and dew point control simultaneously at a low cost, in order to produce biomethane suitable for utility pipeline delivery within minimal pretreatment.